When a deposit of petroleum is located in a subterranean formation, one or more wells are drilled into the formation and the petroleum is allowed to flow or is pumped to the surface of the earth during a period of production commonly referred to as primary production. Unfortunately, primary production recovers only a small fraction of the petroleum originally present in the formation. It has become common practice to apply some form of treatment commonly referred to as enhanced oil recovery to the formation to stimulate the production of petroleum, in order to obtain a larger portion of the petroleum from the formation. The commonest form or treatment comprises injecting water into the formation, which displaces a portion of the petroleum through the permeable formation to a remotely located well by means of which it is recovered to the surface of the earth. Various chemicals including viscosity increasing polymers and surface tension reducing surfactants have been incorporated in the injection water, in order to increase the total amount of petroleum PG,5 recovered from a formation. Injection of steam into subterranean formations containing viscous petroleum has been particularly successful, since primary production recovers very little and in some cases, none of the viscous petroleum originally present in the formation, and steam stimulation has resulted in significant production at relatively modest cost. Steam stimulation may involve injecting steam into one or more wells on a continuous basis and recovering oil from remotely located wells, or it may involve injecting steam into a well for a period of time followed by producing petroleum from the same well.
When a well is drilled into a subterranean petroleum formation, it is common practice to establish communication between the interior of the well and the formation over a substantial portion of the vertical thickness of the petroleum formation. When fluids are injected into the formation via these perforations, it is desirable that the recovery fluid enter the formation relatively evenly, e.g. half of the fluid enters the top half of the formation and half of the fluid enters the bottom half of the formation. Unfortunately, distributions in permeability in formations are so uneven that it is frequently observed that a substantial portion of the steam is entering only a very small portion of the total thickness of the petroleum formation. Oil field service companies offer well surveys which can measure and determine the injectivity profile of an interval, which indicates how evenly the fluid is entering the formation. If the injectivity profile is unfavorable, meaning a major portion of the recovery fluid is entering only a small portion of the thickness of the formation, then the effect of fluid injection on the well will be greatly reduced and some type of remedial treatment must be applied if a significant portion of the oil present in the formation is to be produced by the enhanced oil recovery process.
This problem has been long recognized by persons working in this particular area, and many prior art methods describe processes to be applied to wells for the purpose of altering the fluid injectivity profile of an interval penetrated by a well to a more favorable profile, e.g., to reduce the permeability of the more permeable intervals substantially without reducing the permeability of the less permeable intervals to a similar extent. A great many prior art references describe formation treating processes employing polymers such as carboxymethylcellulose which is injected into the formation, and cross-linking of the polymer within the formation is caused by the presence of trivalent ions such as chromium which, depending on the particular application, are injected previously or subsequently to the polymeric fluid. Many of these processes require successive injections of fluids in order to accomplish sufficient cross-linking of the polymers to accomplish significant reduction of permeability in the very high permeability zones, sometimes referred to as thief zones, in formations, in order to improve the injectivity profile of a subsequently applied oil recovery process involving injection of fluid into the formation for the purpose of stimulating oil production.
Other prior art methods involve injecting polymers into the formation which can be caused to thicken after they have entered the formation.
While many of these procedures have enjoyed success in certain situations, many formations have not responded favorably to prior art methods for a variety of reasons. Many treatment processes require injection of a plurality of different slugs into the formations to interact, and this greatly increases the time and cost of the treatment procedure. Many of the compounds utilized are quite expensive, and this also adds significantly to the cost of the permeability altering processes.
When the oil recovery method to be applied to a formation involves injection of steam, yet another weakness of prior art methods is encountered. Many of the polymers employed in prior art methods are not stable at the high temperatures encountered during the injection of steam into the formation, which may run from 220.degree. to 700.degree. F., and therefore these procedures cannot be employed when steam is to be injected into the formation.
In view of the foregoing brief discussion, it can be appreciated that there is an unfulfilled need for a relatively inexpensive process that can be applied to formation to reduce the wide variations in permeability of the formation. There is a particularly serious unfulfilled need for a process to be applied to a subterranean formation which will resist the temperatures of subsequently injected high temperature fluids such as steam.